Permanent production packer pushes limits of ultra-HPHT wells

Upper completion technology for as-rolled casing sets new technological boundary at 20,000 psi, 470°F

By James Doane, Guijun Deng, Scott Collins, Gary Anderson, Goang-Ding Shyu, Baker Hughes Inc

Figure 1: While designations continue to change as industry ventures to deeper reservoirs in deeper waters, HPHT is currently defined as 20,000 psi and 450°F and ultra-HPHT is typically considered anything above.

As operators continue to drill in deeper and more extreme formations, the demand for technologies to suit these environments will steadily increase. Great efforts have been made over the years to overcome the hurdles to develop safe and reliable completion tools qualified for conditions in excess of 15,000 psi and 450°F. A new technological boundary was set recently in permanent production packer development – the first 20,000-psi, 470°F permanent production packer for as-rolled casing.

A modified ISO 14310 V3 validation test was conducted on this permanent packer in as-rolled casing ID. The packer passed the test with no visible seal element extrusion, no slip damage, and there were no leaks detected at any of the load points in the test, including a bubble test.

The criteria for designating fields as HPHT (Bellarby, 2009) have been changing over the years. In the past, it was fields with pressure greater than 10,000 psi and temperatures higher than 300°F (Maldonado, 2005). Currently, HPHT designation tends to be at 20,000 psi and 450°F. The term ultra-HPHT is typically used to define well environments that are above 20,000 psi and 450°F.

Design verification (analysis) and validation (testing) for HPHT packers and bridge plugs has generally been in accordance with the ISO 14310 (API 11D1) standard. Specifically for casing conditions, ISO 14310 defines that the packer or bridge plug has to be validated in the maximum ID of the rated casing or tubing sizes and weights.  To meet this requirement, most of the manufacturers tested the packer and bridge plug within a machined maximum casing ID, assuming that maximum casing ID is a reasonably severe casing condition.

However, nuances of a packing element system design may result in pressure containment limits in some systems compared with others when set in an imperfect (out-of-round) casing ID. In-house tests of certain packing element designs indicated that a packer or bridge plug rated according to ISO 14310 standards functioned to higher pressure limits in maximum machined ID casing but was inconsistent in as-rolled ID casing.

Figure 2: For as-rolled casing, geometric imperfection could be due to four types of defects: eccentricity, ovality, thickness and ID size variance.

In other words, the design validation and verification process of a new packing element seal system should include consideration of its ability to conform to expected irregularities since it can be more difficult for a packer or bridge plug to pass the testing in as-rolled casing than in maximum machined ID casing.

Casing ID quality is largely due to irregularities inherited from the casing manufacturing process. First, the geometric imperfection can be categorized by eccentricity, ovality, thickness variance and ID size variance (Figure 2). For as-rolled casing, geometric imperfection (Deng, 2010) could be the combination of these four defects, and the bigger ID profile variation compared with machined casing ID presents the greatest challenge.

A resilient and robust backup system for the rubber seal element has to be well designed to provide 360° support in order to prevent element extrusion. Secondly, the as-rolled production casing from operator’s stockpile can be corroded, and its ID surface is relatively rough (Figure 3). Pits, crevices and other surface defects are often visible in the ID of as-rolled casing.

Figure 3: As-rolled production casing can be corroded and have a relatively rough ID surface. Pits, crevices and other surface defects are often visible in the ID of as-rolled casing.

The objective of the project was to design a packer for 6.625-in., 58.8 to 60.8 lb/ft casing. The packer was rated to pressure from below to 20,000 psi and pressure from above to 17,000 psi at 470°F. Validation testing was conducted with water to all the rating envelope points at 470°F with a cool-down to 300°F and heated back to 470°F. Customer-supplied as-rolled casing was used for testing, in addition to the maximum machined ID casing.

To enhance performance in as-rolled-casing and ultra-HPHT applications, the two concepts considered for the new seal design were:

• The Three-piece Element System, rated to 15,000 psi and 350°F. It has been qualified for applications with a groove up to 0.040 in. deep on the ID of the casing (Humphreys, 2009); and

• The Radially Expanded Element System (Doane, 2012), rated to 15,000 psi and 500°F.

Figure 4 : To enhance performance in as-rolled casing and ultra-HPHT applications, a new seal design combined the best aspects of the Three-piece Element System and the Radially Expanded Element System.

The new seal design combines the best aspects of both designs. The thin metal backup profile from the Three-piece Element System was coupled with the Radially Expanded seal setting action.  The combination resulted in an optimized design (Figure 4) that can be set at higher temperatures and hold higher pressures with improved performance in irregular as-rolled casing.

Slips System

Figure 5 : To reduce development cost and time, finite element analysis was heavily used for design verification and optimization in the development of the ultra-HPHT packer seal for as–rolled casing.

Tangential slips were used to minimize the stress on the casing and packer body. Tangential slips have a large contact area with the casing, which reduces the pressure that the slips apply to the casing. Also, the design of the tangential slip system prevents collapse loads from being applied to the packer body. This design causes the slips to apply a tangential load to the slip seat instead of radial load, which keeps the load off

. Figure 6 : A new production packer was installed in a test cell with customer-supplied as-rolled casing to test if the packer could hold pressure at 20,000 psi at the maximum temperature of 470°F and the minimum temperature of 300°F.

the packer body. A double-grip slip system design will ensure that the seal system movement will be minimal under both tension and compression loads, and therefore the risk of damaging the seal system on as-rolled

Figure 7 : A performance envelope was plotted to show each rating point based on the test results of five load cases.

casing will be decreased.

Other accessories

The packer was designed to minimize the burst pressure on the casing and the collapse pressure on the packer body. A body lock ring between the slips and swage prevents the swage from applying force to the seal with pressure differential above the packer. The pressure above acts on the area from the seal ID to the swage ID to create an axial force on the swage. If there was no body lock ring, this axial force would be applied to the seal, which would apply a radial force on the casing. This radial force would be very high due to the shallow angle on the swage. Instead, the axial force is restrained by the body lock ring.

Material selection and characterization

Perfluoroelastomer (FFKM) was chosen as the rubber material because of its temperature and chemical resistance. FFKM has the highest temperature rating (greater than 450°F) and best chemical resistance of any known elastomer. Since the application for this seal is for the harshest well environments, FFKM is the optimal choice. The compound chosen is stable in oil, amines, H2S, CO2 and zinc bromide. In addition, the compound is stable up to 500°F and is NORSOK-qualified for explosive decompression.

Nickel alloy C-276 was chosen as the material for the seal carrier because of its excellent ductility, corrosion and cracking resistance. The material properties of C-276 at various temperatures, such as room temperature, 250°F and 500°F, have been determined because they are critical data for design optimization

Design verification and optimization

To reduce development cost and time, finite element analysis was heavily used for design verification and optimization in the development of the ultra HPHT packer seal in as–rolled casing (Figure 5).

To be considered as a viable design, the following criteria must both be met:

1. The equivalent plastic strain in the metal should not exceed the maximum allowable plastic strain, and the maximum elastic strain in the seal should not exceed the maximum allowable strain; and

2. The seal must be able to set and withstand 20,000 psi above and 17,000 psi below without packing element extrusion.

Figure 8 : After the validation test to determine if the packer could hold pressure at 20,000 psi at 470°F, the packer seal system showed no visual element extrusion.

The process was repeated until an optimum seal design was achieved, and then a 3-D FEA model was set up to identify the minimum setting force. The 2-D FEA model assumed the casing ID was perfectly round, and the 3-D FEA model took into consideration the as-rolled-casing ID profile with as much as 0.050-in ID variance.

This new production packer (Figure 6) was installed in a test cell with customer- supplied as-rolled casing. The ID profile varied 0.050 in. The variation was due to eccentricity and lobes.  The variation due to eccentricity was 0.020 in., and the variation due to the lobes was 0.030 in. The validation testing was conducted with water to all the rating envelope points at 470°F with a cool-down to 300°F.

Figure 9 : Test results of the permanent packer slips system showed no signs of damage to any of the system components.

Test objective

The objective was to determine if the packer could hold pressure at 20,000 psi at the maximum temperature of 470°F and the minimum temperature of 300°F.

Test load cases

The following seven load cases were tested using water as the medium:

I. Rating envelope point #1 (20,000 psi pressure below with 150,000-lb tension at 470°F);

II. Rating envelope point #2  (300,000 lbs of tension at 470°F);

III. Rating envelope point #3 (17,000 psi pressure above with 175,000-lb tension at 470°F);

IV. Rating envelope point #4 (17,000 psi pressure above with 300,000-lb compression at 470°F) and temperature cycle (470°F-300°F-470°F); and

V. Rating envelope point #5  (20,000 psi pressure below with 300,000-lb compression at 470°.

In addition to the testing outlined above, a nitrogen test was conducted on load case I and V.

Test results

A performance envelope was plotted (Figure 7) based on the test results of the five load cases.

At the end of the test, the test fixture was disassembled. The casing was cut open to remove the packer. Figure 8 shows the tested seal unit after the test. No visual element extrusion was identified on the seal element and seal insert.

Figure 9 shows the packer slip system after the test. There was no damage to any of the packer slip components after the test.

A major milestone in upper completion technology has been achieved. For the first time, a permanent production packer was successfully built to seal a pressure of 17,000 psi from above and 20,000 psi below at both 300°F and 470°F in as-rolled casing.

This article is based on a presentation at the 2013 International Petroleum Technology Conference, 26-28 March, Beijing.

References

Bellarby, J., Well Completion Design. 2009, 1st edition, Elsevier, Amsterdam, p. 639-641.

Deng, G., Shyu, G, “An Innovative Approach to Optimizing Design of HP/HT Well Tubular Strings,” SPE 132550, 2010 SPE ATCE, Florence, Italy, 19-22 September 2010.

Doane, J., Deng, G., Collins, S., “A Completion Technology Milestone – The First 25,000-psi 500°F Packer Seal System,” SPE 159182, 2012 SPE ATCE, San Antonio, 8-10 October 2012.

ISO 14310: 2008, Petroleum and Natural Gas Industries – Downhole Equipment-Packer and Bridge Plug.

Maldonado, B, September/October 2005, “Special Design Strategies Vital as HPHT Completion Edge Towards 500°F, 30,000 psi.” Drilling Contractor, Proc. SPE/IADC Drilling Technology Conference, Aberdeen.

Humphreys, A., Ross, R, “Delivering a Fully Qualified HP/HT Production Packer Following Field Failure,” March 2009 SPE Drilling & Completion.

Shyu, G, “Review of the Application of FEA to the Development of WL and Premier Packer,” MSC Software 2007 Virtual Product Development Conference.

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Marathon Oil: 3,000-plus wells possible in Eagle Ford acreage

By Joanne Liou, associate editor

Marathon Oil forecasts its production from US resource plays will increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said at the 2013 IADC Drilling Onshore Conference.

Marathon Oil has determined that it may drill more than 3,000 wells in its Eagle Ford acreage, up from an earlier estimate of approximately 1,200. In fact, the company expects production from its US resource assets, which also include the Bakken and the Woodford, to increase by 150% from Q3 2011 to Q4 2013, Bryan Roy, vice president – drilling & completions for Marathon Oil, said. “When you talk about shale and moving the needle for a company that is producing between 400,000 and 450,000 bbls/day, that is substantial,” Mr Roy said during a presentation at the 2013 IADC Drilling Onshore Conference on 16 May in Houston.

For Marathon, the impact that US resource plays are having on the company’s portfolio is significant. As an example, its US business once provided capital for large expenditures overseas, but that pendulum has swung in the opposite direction due to the growth in US unconventionals. “Now, a lot of Equatorial Guinea and Norway production is funding a lot of capital in the US,” Mr Roy said. “We are targeting 5% to 7% average growth rate (in production) across the world.”

Marathon currently has 16 rigs working in the Eagle Ford and expects to spend nearly $2 billion in that play this year, according to Mr Roy. “One of the challenges we continue to have is we tend to overspend our capital because we keep drilling wells so fast,” he stated. “That will continue to be a problem, I hope, because it’s a mark of efficiency.” The company also continues to study its approach to developing its Eagle Ford acreage, such as optimal well density, lateral lengths and completion techniques. “A lot of pilots in the ground now are already completed … and the science looks good. We spent a lot to get into the Eagle Ford, but it’s looking a lot better than what we thought it was going to be,” he said, referring to the increase in the number of estimated wells.

Outside of the US, Marathon also continues an aggressive exploration program in Kurdistan in northern Iraq, where the company made entry in 2010. It currently has two rigs drilling in the Harir and Safen blocks, which Marathon believes have “the potential for the largest unexplored basins in the world,” Mr Roy said. “We are very interested to see how productive the wells could be.”

The region does come with significant operational challenges, however, from security issues to high H2S concentrations in the ground. In fact, some zones can carry up to 22% H2S combined with 13% CO2, Mr Roy said, making it a challenge to complete and make long-term production adequate. Other challenges include lost circulation and issues with primary cement jobs and directional control. Beyond that, “we still have significant issues relative to emergency response plans and evacuations that could be required,” he noted.

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Baker Hughes to Present at the Wells Fargo Securities MLP Pipeline and E&P, Energy Services & Utility Symposiums

HOUSTON, Dec 03, 2009 /PRNewswire-FirstCall via COMTEX News Network/ -- Baker Hughes Incorporated (NYSE: BHI) announced today that Peter Ragauss, Senior Vice President and Chief Financial Officer, will present at the Wells Fargo Securities MLP Pipeline and E&P, Energy Services & Utility Symposiums in New York, NY on December 9, 2009, at 8:00 a.m. eastern time.

If you would like to listen to the presentation during the conference, please log on to the following website: http://investor.shareholder.com/bhi/events.cfm. If you would like to listen to a replay of the panel, it will be available within 24 hours of the live presentation and will remain available through December 23, 2009. Use the same website address above to access the replay.

Forward-Looking Statements

The presentation referenced in this news release and any oral statements made in connection with the presentation may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934 as amended. Additional information and risk factors are contained in our Form 10-K for the fiscal year ended December 31, 2008 and other filings with the SEC about the risks and uncertainties that could cause actual results to be different than those in our presentation. The company's SEC filings can be viewed at www.bakerhughes.com. The company assumes no responsibility to update any of the information referenced in this news release.

Baker Hughes is a leading provider of drilling, formation evaluation, completion and production products and services to the worldwide oil and gas industry.

NOT INTENDED FOR BENEFICIAL HOLDERS

Contacts:Gary R. Flaharty (713) 439-8039H. Gene Shiels (713) 439-8822

SOURCE Baker Hughes Incorporated

http://www.bakerhughes.com

Copyright (C) 2009 PR Newswire. All rights reserved

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Continuous circulation systems build healthier wells, reduce risk in difficult environments

 

By Linda Hsieh, managing editor, and Katherine Scott, editorial coordinator

Just as humans can be injured even by a short interruption of the blood supply through our arteries and veins, wellbores also need continuous flow through the pipe and annulus to prevent potential harm. That was the analogy used by Angelo Ligrone, vice president logistics for Eni, at the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition on 20 March in Milan, Italy. He presented Eni’s work on two proprietary technologies – a circulation device called the e-CD and a near-balance drilling technology called e-NBD. The company has used both to significantly reduce risks during the drilling process, particularly in difficult deepwater drilling environments.

Angelo Ligrone presented work related to Eni’s e-CD and e-NBD are proprietary technologies, which that enable the company to maintain constant bottomhole pressure with continuous circulation, at the 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition on 20 March in Milan, Italy.

“If we can get performance but without safety, this is not performance. Safety and performance have to come hand in hand,” said Mr Ligrone, who until recently served as vice president of drilling technology for Eni.

The e-CD, introduced in 2005, is a system that allows for continuous mud circulation to maintain constant bottomhole pressure while making up or breaking out drill pipe connections during drilling operations. “We have controlled the ECD (equivalent circulating density) throughout the drilling process, thus eliminating mud pressure fluctuations,” Mr Ligrone explained. This in turn prevents problems such as wellbore instability, as well as reduces nonproductive time.

In 2010, Eni introduced e-NBD, a technology born out of the company’s success with the e-CD. “By adding a rotating BOP and bringing it down on top of the conventional BOP stack and the active choke system, the e-CD becomes the e-NBD system,” he said. The technology allows for the maintenance of constant bottomhole annular pressure at all times while circulating and to manage the annular dynamic hydraulic pressure profile. “The benefits indeed are well control and safety first of all … and improving hole conditions.”

He added that e-NBD is an enabling technology helping Eni get to targets where conventional technologies cannot, particularly for operations within narrow pore/fracture pressure gradients, as well as for HPHT and underbalanced operations. In March 2008, for example, Eni completed its first e-NBD HPHT well in Egpyt at 5,450 meters TD; this “nightmare” scenario involved 2.25 sg mud, 2.23 pore gradient and 2.26 equivalent mud weight fracture gradient.

In another example offshore Libya, the e-NBD system was deployed from a floating rig to reenter a temporarily abandoned exploration well where drilling activities had been stopped due to conventional drilling limits. The bottomhole target was reached without problems using e-NBD, Mr Ligrone said.

Onshore as well, the technology has been used in difficult drilling environments. A vertical land well in Pakistan used e-NBD to drill the 10 5/8-in. and 8 ½-in. sections to reach the gas targets. “The decision to drill the section with the e-NBD system was taken based on the fact that such phases were explorative, and the only data available from one reference well in the area was showing a high formation pressure with an incremental trend of the pore pressure gradient,” he said. The reference weight had been suspended due to continuous formation pressure increase and strong gas showed a high percentage of gas present and well construction limitations, he continued.

“I will stress again that safety and performance have to go hand in hand. We cannot have performance without safety or safety without performance,” Mr Ligrone emphasized. “They are essential in ensuring a sustainable drilling business. Continuous circulation is recognized as a key factor for safer and faster drilling.”

e-CD and e-NBD are trademarks of Eni.

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